Method for syngas separation at hydrogen producing facilities for carbon capture and storage

ABSTRACT

Methods and systems for gas separation of syngas applying differences in water solubilities of syngas components, the method including producing a product gas comprising hydrogen and carbon dioxide from a hydrocarbon fuel source; separating hydrogen from the product gas to create a hydrogen product stream and a byproduct stream by solubilizing components in water that are more soluble in water than hydrogen; injecting the byproduct stream into a reservoir containing mafic rock; and allowing components of the byproduct stream to react in situ with components of the mafic rock to precipitate and store components of the byproduct stream in the reservoir.

PRIORITY

The present application is a divisional application of U.S. patent application Ser. No. 16/505,379, filed on Jul. 8, 2019, which is itself a non-provisional patent application of and claims priority to and the benefit of U.S. Prov. App. Ser. No. 62/830,949, filed Apr. 8, 2019, the entire disclosures of which are incorporated here by reference.

BACKGROUND Field

Embodiments of the disclosure relate to synergistic hydrogen production and carbon capture. In particular, embodiments of the disclosure relate to hydrogen production from fossil fuels with water-based syngas separation and carbon capture via mafic rock, for example basalts.

Description of the Related Art

Hydrogen or H₂ is an environmentally-friendly fuel which has the potential to replace greenhouse gas emitting hydrocarbon fuels. For example, hydrogen can be used to power fuel cells. Nearly all H₂ currently produced, greater than about 95%, is derived from hydrocarbons, and predominantly from natural gas. Waste CO₂ released to the atmosphere (between about 7 and 12 tons CO₂ per ton of H₂ produced) partially negates the “clean fuel” benefits of H₂. To mitigate the carbon footprint of H₂ production, economically-impractical methods and systems have been proposed for H₂ production combined with capturing, compressing to a liquid, and injecting co-produced CO₂ into deep (greater than about 800-850 m underground) sedimentary rock reservoirs in a process known as carbon capture and storage (“CCS”). However, conventional CCS adds significant cost to an already highly-energy-consuming H₂ production process, thus rendering the combined technology unfeasible under current market and regulatory conditions.

Previously-proposed combinations of H₂ production from hydrocarbons with conventional CCS of CO₂, for example in depleted hydrocarbon reservoirs or saline groundwater aquifers, adds significant costs associated with purification, compression, transportation, and injection of CO₂. A number of energy-consuming steps are employed to ensure high purity of CO₂ (greater than about 98 mol. %) needed to meet the requirements of conventional CCS. And, since standard pressure swing adsorption (“PSA”) H₂—CO₂ separation technology alone does not produce CO₂ of sufficient quality and purity for CCS, further purification involving acid gas absorbing reagents, such as Selexol™ (for heavy and solid hydrocarbons) and methyl diethanolamine (MDEA), is needed.

Safe and economic transportation, as well as the injection and long-term storage of CO₂ in conventional CCS, depends upon CO₂ being compressed to a supercritical (liquid) state, which also adds significant cost. Consequently, underground CO₂ storage reservoirs must be located at least about 850 vertical meters below the ground surface to ensure that there is sufficient pressure to keep CO₂ in a liquid state, thus adding to the cost of the injection and disposal wells.

Since CO₂ in conventional CCS could remain in a liquid and/or compressed gas state for hundreds or thousands of years, sophisticated long-term monitoring programs are needed to ensure that CO₂ is truly confined to a given CCS reservoir and does not migrate to overlying aquifers or the surface.

SUMMARY

The present disclosure presents systems and methods for efficient H₂ separation from syngas during production of hydrogen from hydrocarbon fossil fuels with little to no greenhouse gas emissions. In some embodiments, the first step of the method is co-production of H₂ and waste or byproduct CO₂ from gaseous, liquid, or solid hydrocarbons (for example steam reforming of natural gas). The co-production of H₂ and CO₂ from hydrocarbons can be accomplished in various processes. In a second step, water-based separation technologies are used to separate H₂ from other gas components, such as CO₂ and H₂S, based on differences in gas-water solubilities. In a third step of the method, water saturated with byproduct components, such as CO₂ and H₂S for example, is injected into reactive mafic or ultramafic rocks, where CO₂ and/or other waste gases are permanently immobilized as precipitated carbonate minerals.

The term mafic generally describes a silicate mineral or igneous rock that is rich in magnesium and iron. Mafic minerals can be dark in color, and rock-forming mafic minerals include olivine, pyroxene, amphibole, and biotite. Examples of mafic rocks include basalt, diabase, and gabbro, and examples of ultramafic rocks include dunite, peridotite, and pyroxenite. Chemically, mafic and ultramafic rocks can be enriched in iron, magnesium, and calcium.

The versatility of the present carbon capture and storage (“CCS”) systems and methods also allows CO₂ from other sources such as refining, power production, and desalinization to be immobilized economically and permanently, for example in basaltic rock. In embodiments of systems and methods described here, by passing syngas through a reaction vessel such as a scrubber column with water, CO₂ and acid gases are dissolved in the water, which can be permanently disposed in basaltic rocks, in some embodiments without or in the absence of further separation, purification, or compression. The separated H₂ product can proceed for further treatment as needed, and ultimately be transported for use as a fuel product. In embodiments of systems and methods, produced hydrogen can be converted reversibly to ammonia for safe storage and transportation in a reduced volume.

To increase the efficiency of synergistic H₂ production with CO₂ removal, H₂ production occurs preceding an alternative CCS process in which CO₂ is injected into natural geological sinks comprised of reactive basaltic and ultramafic lithologies, where it rapidly reacts to form stable mineral phases, such as precipitated carbonates. Carbon storage in basalts (“CSB”) consumes significantly less energy than other CCS systems and processes, has advantageously high tolerance to acid gas impurities (i.e., H₂S), does not require deep wells, such as those 850 m deep or deeper, and does not require long-term reservoir monitoring.

Storage of CO₂ in basaltic and ultramafic rocks is unique compared to conventional CCS, because it relies in part on rapidly proceeding chemical reactions which convert CO₂ gas to solids, rather than relying on physical storage of CO₂ itself over time. Economic estimates demonstrate the cost for one metric ton of CO₂ captured by presently disclosed systems and methods is substantially less compared to conventional CCS.

In some embodiments, CO₂ gas is dissolved in water prior to or during injection into a basalt-containing reservoir, and this avoids difficulties including compressing and maintaining CO₂ in a liquid state. Having CO₂ dissolved in an aqueous phase helps avoid the need for drilling deep disposal wells deeper than about 850 m below the surface, as is required in conventional CCS. In other words, significantly lower pressures are needed to keep sufficient quantities of CO₂ dissolved in water, and injection zones can be as shallow as 350 vertical meters below surface for embodiments of the present disclosure.

Rapid immobilization of CO₂ as solid, stable carbonate minerals not only ensures permanent removal of CO₂ from the environment, but also precludes the need for sophisticated monitoring programs needed at conventional CCS sites. Extreme tolerance of the present technology to the presence of up to about 40 mol. % of other water soluble waste gases such as H₂S, which like CO₂ is rapidly and substantially completely mineralized in basalts and ultramafics, also has important efficiency implications.

CSB negates the need for expensive and energy consuming steps to remove sulfur/H₂S impurities from CO₂ and other gases produced during H₂ production. Another important advantage is that in contrast to liquid CO₂, which is less dense than reservoir water and thus buoyant, CO₂-rich water has higher density than ambient groundwater. Consequently, when injected, CO₂-rich water will sink in the reservoir rather than move upwards, which in some embodiments eliminates the need of a caprock—a critically important geological feature of all conventional CCS reservoirs. In embodiments of the present disclosure, injection and storage of CO₂ in basalts and mafics has no impact on the quality of groundwater residing in those lithologies. This is particularly important when such aquifers are used to supply drinking water or water for other purposes.

Therefore, disclosed here is a method for gas separation of syngas applying differences in water solubilities of syngas components, the method including producing a product gas comprising hydrogen and carbon dioxide from a hydrocarbon fuel source; separating hydrogen from the product gas to create a hydrogen product stream and a byproduct stream by solubilizing components in water that are more soluble in water than hydrogen; injecting the byproduct stream into a reservoir containing mafic rock; and allowing components of the byproduct stream to react in situ with components of the mafic rock to precipitate and store components of the byproduct stream in the reservoir. In some embodiments, the step of separating includes the use of at least one vertical scrubbing tower with countercurrent flow of the product gas and water, the product gas flowing at about 20° C. In other embodiments, at least about 50% of CO₂ and about 95% of H₂S are removed from the product gas and separated from the hydrogen product stream by being solubilized in the countercurrent flow of water.

Still in other embodiments, the step of separating includes the use of at least two vertical scrubbing towers in series with countercurrent flow of the product gas and water. In some embodiments, the mafic rock comprises basaltic rock. In some other embodiments, before the step of injecting the byproduct stream into the reservoir, the byproduct stream is further treated to separate and purify CO₂ from other components to increase CO₂ concentration of the byproduct stream for injection into the reservoir. Still other embodiments of the method include the step of liquefying CO₂ in the byproduct stream for injection into the reservoir. Certain embodiments include the step of reacting the separated hydrogen with nitrogen to form compressed liquid ammonia.

In yet other embodiments of the method, included are the steps of transporting the compressed liquid ammonia and returning the compressed liquid ammonia to hydrogen and nitrogen via electrolysis for use of hydrogen as a hydrogen fuel source. In some embodiments, the step of producing a product gas includes steam reforming or partial oxidation. Still other embodiments include the step of allowing components of the byproduct stream to react in situ with components of the mafic rock to precipitate products selected from the group consisting of: calcium carbonates, magnesium carbonates, iron carbonates, and combinations thereof. Still in other embodiments, the reservoir is between about 250 m and about 700 m, or is between about 400 m and about 500 m, below the surface and is between about 150° C. and about 280° C., or less. Temperatures in suitable reservoirs can be as low as about 30° C. In other embodiments, the reservoir is between about 700 m and about 2,200 m below the surface and is less than about 325° C.

Additionally disclosed here is a system for gas separation of syngas applying differences in water solubilities of syngas components, the system including a hydrogen production unit with a hydrocarbon fuel inlet operable to produce a product gas comprising hydrogen and carbon dioxide from hydrocarbon fuel; a hydrogen separation unit operable to separate hydrogen from the product gas to create a hydrogen product stream and a byproduct stream by solubilizing components in water that are more soluble in water than hydrogen; and an injection well operable to inject the byproduct stream into a reservoir containing mafic rock to allow components of the byproduct stream to react in situ with components of the mafic rock to precipitate and store components of the byproduct stream in the reservoir.

In some embodiments of the system, the hydrogen separation unit includes at least one vertical scrubbing tower with countercurrent flow of the product gas and water, the product gas flowing at about 20° C. In some embodiments, at least about 50% of CO₂ and about 95% of H₂S are removed from the product gas and separated from the hydrogen product stream by being solubilized in the countercurrent flow of water in a single pass through one scrubbing tower. Still in other embodiments, the hydrogen separation unit includes at least two vertical scrubbing towers in series with countercurrent flow of the product gas and water. In some embodiments of the system, the mafic rock comprises basaltic rock.

Some embodiments include a byproduct treatment unit to treat the byproduct stream to separate and purify CO₂ from other components and to increase CO₂ concentration of the byproduct stream for injection into the reservoir. Other embodiments include a compressor to liquefy CO₂ in the byproduct stream for injection into the reservoir. Still other embodiments include a reaction unit to react the separated hydrogen with nitrogen to form compressed liquid ammonia. In certain embodiments of the system, included is a transportation unit to transport the compressed liquid ammonia and return the compressed liquid ammonia to hydrogen and nitrogen via electrolysis for use of hydrogen as a hydrogen fuel source.

In yet other embodiments, the hydrogen production unit includes a steam reformer or partial oxidation reactor. In some embodiments, components of the produced byproduct stream react in situ with components of the mafic rock to precipitate products selected from the group consisting of: calcium carbonates, magnesium carbonates, iron carbonates, and combinations thereof. Still in other embodiments, the reservoir is between about 250 m and about 700 m, or is between about 400 m and about 500 m, below the surface and is between about 150° C. and about 280° C., or less. Temperatures in suitable reservoirs can be as low as about 30° C. In other embodiments, the reservoir is between about 700 m and about 2,200 m below the surface and is less than about 325° C.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of the present disclosure will become better understood with regard to the following descriptions, claims, and accompanying drawings. It is to be noted, however, that the drawings illustrate only several embodiments of the disclosure and are therefore not to be considered limiting of the disclosure's scope as it can admit to other equally effective embodiments.

FIG. 1 shows a schematic flow chart for an example embodiment of a system for simultaneous H₂ production, H₂ water-solubility-based separation, and CO₂ sequestration for producing H₂ from hydrocarbons with near zero greenhouse gas emissions.

DETAILED DESCRIPTION

So that the manner in which the features and advantages of the embodiments of systems and methods for efficient H₂ separation from syngas during production of hydrogen from hydrocarbon fossil fuels, with little to no greenhouse gas emissions, as well as others, which will become apparent, may be understood in more detail, a more particular description of the embodiments of the present disclosure briefly summarized previously may be had by reference to the embodiments thereof, which are illustrated in the appended drawings, which form a part of this specification. It is to be noted, however, that the drawings illustrate only various embodiments of the disclosure and are therefore not to be considered limiting of the present disclosure's scope, as it may include other effective embodiments as well.

The production of H₂ from hydrocarbons using technologies such as steam-reforming or partial oxidation/gasification includes three steps. In steam reforming, hydrocarbons, for example methane, are heated in the presence of H₂O (steam) and catalysts to release raw syngas consisting of hydrogen (H₂), carbon monoxide (CO), small amounts of carbon dioxide (CO₂), and/or other impurities as shown in Equations 1 and 2:

CH₄+H₂O↔CO+3H₂  Eq. 1

and/or

C_(n)H_(m) +nH₂O↔nCO+(n+0.5 m)H₂  Eq. 2

The raw syngas is then treated to remove sulfur compounds and/or purified further. H₂ yield is then maximized by reacting the raw syngas with H₂O steam in the presence of catalyst to produce H₂ and CO₂ according to Equation 3:

CO+H₂O→CO₂+H₂  Eq. 3

This is known as a water-gas shift reaction, hence the product is called “shifted” syngas. In partial oxidation, hydrocarbons are reacted with small (non-stoichiometric) amounts of oxygen (O₂) to produce raw syngas consisting of H₂ and CO according to Equation 4:

CH₄+½O₂→CO+2H₂  Eq. 4

This raw syngas also contains minor amounts of CO₂ and/or nitrogen (N₂, if air was used instead of pure O₂). The raw syngas is then purified, and its H₂ content maximized by the reaction of Equation 3. The composition of an example shifted syngas produced by both processes (steam reforming and partial oxidation) is presented in Table 1:

TABLE 1 Example shifted syngas composition from steam reforming or partial oxidation. Component H₂ CO CO₂ N₂ O₂ Ar H₂S H₂O Other Mol. % 40.9 1 29.8 2.4 0 0.4 0.01 25.4 0.11

Following water-gas shift, H₂ is conventionally purified by separation from CO₂ and other impurities by processes that employ adsorption, absorption, and/or membrane filtration. Membrane technologies have been developed, but are not yet widely-used on an industrial scale. One example process is Pressure Swing Adsorption (“PSA”), which uses pressure-dependent selective adsorption properties of materials such as activated carbon, silica, and zeolites. Waste or byproduct CO₂ and other impurities separated from H₂ during PSA are then vented to the atmosphere. Unfortunately, if a conventional CCS scheme were to be used to sequester CO₂, then the CO₂ must be purified further and compressed to a liquid (supercritical) state for transportation and injection into a deep reservoir. Both steps, however, are avoided (or simplified significantly) here when CSB is applied instead.

PSA is energy intensive and increases the cost and complexity of obtaining a final substantially pure H₂ product. In systems and methods of the present disclosure, PSA or other conventional H₂-syngas separation systems can be reduced in size or replaced entirely with a surprisingly and unexpectedly efficient technology which employs significant differences in water solubility between H₂ and CO₂ (and/or other acid gases). In embodiments of the present disclosure, syngas produced after water-gas shift is cooled to about 20° C. and injected into the base of a vertical pressurized vessel, for example a scrubbing tower, where dispersed gas interacts with and intimately intermingles with a stream of water fed from the top of the vessel and dispersed throughout the vessel. To maximize contact between dispersed gas and water, the tower is packed with a filling or channels that create highly tortuous pathways. Consequently, CO₂ (and/or other water soluble gases) dissolve in the water, whereas H₂ (and/or other insoluble gases) accumulate at the top of the vessel for collection and/or further treatment/purification.

While conventional CCS relies predominantly on physical processes such as the injection and storage of single phase liquid CO₂ in non-reactive rock reservoirs (e.g., sandstone, limestone), CSB relies on the naturally occurring chemical reactions between CO₂ and mafic and ultramafic rocks to precipitate solid carbonates. Reactions include the following: first CO₂ dissolves in and reacts with water (either or both water supplied with CO₂ gas at the surface or water present in situ in a mafic reservoir) to form a week carbonic acid as shown in Equations 5-7:

CO₂+H₂O↔H₂CO_(3(aq))  Eq. 5

H₂CO₃↔HCO₃ ⁻+H⁺  Eq. 6

HCO₃ ⁻↔CO₃ ²⁻+H⁺  Eq. 7

Acidified water dissolves Ca, Fe, and Mg-rich silicate phases (minerals and/or volcanic glass) which results in the release of divalent metal ions in solution according to Equation 8:

(Mg,Fe,Ca)₂SiO₄+4H⁺→2(Mg,Fe,Ca)²⁺+2H₂O+SiO_(2(aq))  Eq. 8

CO₃ ²⁻ formed during the reaction shown in Equation 7 reacts with the divalent metal cations leading to the precipitation of carbonate minerals as shown in Equation 9:

(Ca,Mg,Fe)²⁺+CO₃ ²⁻→(Ca,Mg,Fe)CO₃  Eq. 9

Geochemical reaction-transport modeling demonstrates that mineral phases (for example calcite, siderite, and magnesite) will remain stable under prevailing subsurface conditions, hence safely removing CO₂ from the atmosphere for hundreds of thousands to millions of years. Other carbonate minerals include ankerite Ca[Fe, Mg, Mn](CO₃)₂. In addition, CSB has extreme tolerance for other water soluble acid gas impurities (e.g. H₂S, which is also mineralized as sulphides). Such an advantageous quality not only simplifies the process further, eliminating the need to remove those impurities from a gas mixture exiting an H₂ production process, but it also allows for simultaneous sequestering of all other H₂O soluble gas contaminants capable of forming stable mineral phases by reacting with basalts/mafics.

CO₂ dissolution in water for CSB can be achieved by either: a) separately injecting CO₂ and water in the tubing and annular space of injector wells and allowing these to mix at or below about a 350 m depth in the wellbore prior to entering the reservoir; or b) dissolving CO₂ and water at the surface in a pressurized vessel and then injecting the solution in a basalt/ultramafic reservoir. While the first method generally applies to pure CO₂ and/or a mixture of CO₂ and other water soluble acid gases, the latter method is used to effectively separate CO₂ (and other water soluble gases) from insoluble or weekly soluble impurities, and can therefore be used to process complex flue gas mixtures (e.g. shifted syngas).

Due to certain thermodynamic constraints of CO₂ dissolution in water, both methods require about 27 tons of H₂O per 1 ton of CO₂ sequestered. In areas where water is in short supply, CSB may be done by injecting supercritical (liquid) CO₂ in basalts or ultramafics; however, this would increase energy demands due to the need for liquefying CO₂ via compression.

With respect to the produced H₂, conventionally H₂ is stored and transported as a liquid at a temperature of about −253° C., which requires special double-walled isolated vessels and/or constant refrigeration. However, reversible chemical conversion of H₂ into liquid ammonia (NH₃) allows storage and transportation of H₂ at low pressure and ambient temperatures, at greatly reduced volumes. The reversible H₂ to NH₃ storage and transport method is inherently safer and advantageous in particular where large volumes of H₂ are to be stored and transported.

Due to high tolerance of CSB to impurities in the CO₂ stream (such as H₂S and other gases), CO₂—rich tail gases from other sources such as refining, power production, and desalinization could, after limited treatment, be either added to the principal waste stream or independently injected into reactive lithologies for permanent immobilization and disposal.

Unexpected and surprising advantages of simultaneously producing H₂ from hydrocarbons while using CSB for permanent CO₂ immobilization in basalts and ultramafics include significantly lower predicted energy usage and cost due to: lower energy consumption and lower well costs because there is no requirement to compress and liquefy the CO₂; lower complexity of operations due to high tolerance to impurities in the CO₂ stream; simultaneous removal of H₂S along with CO₂ in the reservoirs via precipitation as solids; no need for a reservoir caprock; and no need for sophisticated long-term monitoring programs. There is no need to liquefy CO₂ when it is dissolved in water either at the surface or in the wellbore, but it can be liquefied if directly injected in the subsurface as supercritical fluid.

FIG. 1 shows a schematic flow chart for an example embodiment of a system for simultaneous H₂ production, H₂ separation, and CO₂ sequestration for producing H₂ from hydrocarbons with near zero greenhouse gas emissions. In system 100, a hydrocarbon inlet 102 provides a hydrocarbon source, for example natural gas, to a hydrogen production system 104. Hydrogen production system 104 might include steam reforming or partial oxidation, and water-gas shift reactions, for example as described in Equations 1-4. Production gases exit via outlet 106 to a separation unit 108. Separation unit 108 is operable to separate hydrogen from CO₂ and other byproducts, such as for example acid gases.

PSA is energy intensive and increases the cost and complexity of obtaining a final substantially pure H₂ product. In systems and methods of the present disclosure, PSA or other conventional H₂-syngas separation systems can be reduced in size or replaced entirely with a surprisingly and unexpectedly efficient technology which employs significant differences in water solubility between H₂ and CO₂ (and/or other acid gases). In FIG. 1 , syngas produced after water-gas shift in hydrogen production system 104 is cooled to about 20° C. and injected into the base of separation unit 108 from outlet 106. Separation unit 108 includes at least one vertical pressurized vessel, for example a scrubbing tower, where dispersed gas interacts with and intimately intermingles with a stream of water fed from the top of the vessel at stream 107. To maximize contact between dispersed gas (including H₂, CO₂, and acid gases such as H₂S) and water, the tower is packed with a filling or channels that create highly tortuous pathways. Consequently, CO₂ (and/or other water soluble gases) dissolve in the water, whereas H₂ (and/or other insoluble gases) accumulate at the top of separation unit 108 for collection and/or further treatment/purification at outlet stream 118.

One purpose of a scrubbing tower is to facilitate an efficient mass transfer of CO₂ and other acid gases, such as H₂S, from a gas phase to a liquid phase. This is carried out through a contact tower filled with high specific surface area media (such as Tri-Mer® Tri-Packs® or Lantec Lanpac® for example) and/or through a low profile tortuous path air bubbler design, optimized specifically for this purpose. Providing maximum surface contact between gas and the scrubbing liquid (water for example) by facilitating continuous formation of droplets throughout the packed bed results in high scrubbing efficiency, and minimizes packing depth.

A suitable residence time in a scrubbing tower can be between about 5 and about 120 seconds, depending on the syngas composition and flow patterns. Temperature can range from about 2° C. to about 55° C. under a pressure range of about 1 atm to about 6 atm. The obtained purity of H₂ will range from about 50-99.9 mol. % depending on the operating conditions and the syngas composition. Embodiments of separation units including at least one scrubbing tower can function under all ranges of CO₂ concentrations in gas phase, and one variable impacted and able to be adjusted is the quantity of water needed, which is also dependent on the operating pressure and temperature.

Water-soluble CO₂ and additional water-soluble gases such as acid gases exit separation unit 108 via outlet 110 mixed with water from stream 107, and can optionally proceed to a further CO₂ purification and liquidification unit 112, but need not to. Water can be supplied via a water supply well, and in some embodiments may be supplied via water in a basaltic reservoir to ultimately be recycled back to the same basaltic reservoir with CO₂ and H₂S dissolved components. In some embodiments using a single scrubbing tower, between about 40% and about 60%, or between about 50% and about 70% of the CO₂ and between about 90% and 100% or between about 97% and about 100% of the H₂S are recovered from the syngas in separation unit 108 and proceed via outlet 110 mixed with water from stream 107. Separation unit 108 in some embodiments can have 1 scrubbing tower, but in other embodiments can have more than 1 scrubbing tower operating in parallel or series.

In the case of further CO₂ purification and liquidification unit 112, liquefied CO₂ is injected into basaltic formation 116 via injection well 114 to form solid precipitated metal carbonates per Equations 5-9. Without optional further CO₂ purification and liquidification unit 112, CO₂ and additional gases such as acid gases exit separation unit 108 via outlet 110 and proceed directly into basaltic formation 116 via injection well 114 to form solid precipitated metal carbonates per Equations 5-9. CO₂ can be mixed with water as a gas at the surface or in situ in basaltic formation 116, or both. Solid carbonate nodules form in vugs and veins in basalt around injection wells and extending outwardly from the injection wells.

Rates of basalt dissolution and mineral carbonation reactions can increase with increasing temperature, and thus higher temperature basaltic reservoirs may be advantageous, while deep reservoirs beyond about 850 m are not required because high pressures are not required to keep CO₂ in a pressurized or liquid state. An example suitable reservoir temperature is about 185° C., or for example between about 150° C. and about 280° C., or less. As explained, injected CO₂, either by itself or with other gases, creates an acidic environment with water near the injection well, such as injection well 114. Near injection well 114, the acidic fluids remain undersaturated with respect to basaltic minerals and volcanic glass.

Undersaturation and acidity leads to dissolution of host rock basalts in the vicinity of injection wells, such as injection well 114. Mineralization then mostly occurs at a distance away from the injection well (which allows continuous injection of CO₂ in a reservoir such as basaltic formation 116), after heat exchange and sufficient dissolution of host basaltic rock neutralizes the acidic water and saturates the formation water with respect to carbonate and sulfur minerals.

Hydrogen exits separation unit 108 at outlet stream 118 to proceed to reaction unit 120 where hydrogen is reacted with nitrogen to form ammonia (NH₃). In some embodiments, before H₂ proceeds to a reaction unit such as reaction unit 120, other H₂ purification techniques such as PSA, absorption, or membrane separation could be carried out as needed based on requirements of the H₂ product. Ammonia exits reaction unit 120 at outlet 122 for reduced volume transport of H₂ as NH₃. Reaction unit 120 can include a pressurized multistage ammonia production system (PMAPS) to produce ammonia in a pressurized liquid phase. Pressurized liquid NH₃ can be transported by a pressurized tanker truck, and using an NH₃ electrolyzer, NH₃ can be reversibly returned to N₂ and H₂ wherever hydrogen is required.

The singular forms “a,” “an,” and “the” include plural referents, unless the context clearly dictates otherwise.

The term “about” when used with respect to a value or range refers to values including plus and minus 5% of the given value or range.

In the drawings and specification, there have been disclosed embodiments of systems and methods for efficient H₂ separation from syngas during production of hydrogen from hydrocarbon fossil fuels with little to no greenhouse gas emissions of the present disclosure, and although specific terms are employed, the terms are used in a descriptive sense only and not for purposes of limitation. The embodiments of the present disclosure have been described in considerable detail with specific reference to these illustrated embodiments. It will be apparent, however, that various modifications and changes can be made within the spirit and scope of the disclosure as described in the foregoing specification, and such modifications and changes are to be considered equivalents and part of this disclosure. 

That claimed is:
 1. A system for gas separation of syngas applying differences in water solubilities of syngas components, the system comprising: a hydrogen production unit with a hydrocarbon fuel inlet operable to produce a product gas comprising hydrogen and carbon dioxide from hydrocarbon fuel; a hydrogen separation unit operable to separate hydrogen from the product gas to create a hydrogen product stream and a byproduct stream by solubilizing components in water that are more soluble in water than hydrogen; and an injection well operable to inject the byproduct stream into a reservoir containing mafic rock to allow components of the byproduct stream to react in situ with components of the mafic rock to precipitate and store components of the byproduct stream in the reservoir.
 2. The system according to claim 1, where the hydrogen separation unit includes at least one vertical scrubbing tower with countercurrent flow of the product gas and water, the product gas flowing at about 20° C.
 3. The system according to claim 2, where at least about 50% of CO₂ and about 95% of H₂S are removed from the product gas and separated from the hydrogen product stream by being solubilized in the countercurrent flow of water in a single pass through one scrubbing tower.
 4. The system according to claim 1, where the hydrogen separation unit includes at least two vertical scrubbing towers in series with countercurrent flow of the product gas and water.
 5. The system according to claim 1, where the mafic rock comprises basaltic rock.
 6. The system according to claim 1, further comprising a byproduct treatment unit to treat the byproduct stream to separate and purify CO₂ from other components and to increase CO₂ concentration of the byproduct stream for injection into the reservoir.
 7. The system according to claim 1, further comprising a compressor to liquefy CO₂ in the byproduct stream for injection into the reservoir.
 8. The system according to claim 1, further comprising a reaction unit to react the separated hydrogen with nitrogen to form compressed liquid ammonia.
 9. The system according to claim 8, further comprising a transportation unit to transport the compressed liquid ammonia and return the compressed liquid ammonia to hydrogen and nitrogen via electrolysis for use of hydrogen as a hydrogen fuel source.
 10. The system according to claim 1, where the hydrogen production unit includes a steam reformer or partial oxidation reactor.
 11. The system according to claim 1, where components of the produced byproduct stream react in situ with components of the mafic rock to precipitate products selected from the group consisting of: calcium carbonates, magnesium carbonates, iron carbonates, and combinations thereof.
 12. The system according to claim 1, where the reservoir is between about 250 m and about 2,200 m below the surface and is between about 30° C. and about 325° C.
 13. The system according to claim 1, where the reservoir is between about 350 m and about 1,500 m below the surface and is less than about 325° C. 